Author: Muaath Alansari Publisher: ISBN: Category : Languages : en Pages : 57
Book Description
"Well stimulation (well fracturing) became an essential tool in the Oil and Gas industry to unlock the potential of unconventional reservoirs all over the world and especially in the Middle East. In Kuwait, well stimulation is obligatory when dealing with deep Jurassic carbonate reservoirs. Thus, the well fracture designing process plays a very critical role in determining the success of the stimulation job and the improvement of the recovery. Several wells stimulated with 20% HCL have shown wide variations in both short and long term well production performance. The research aims to investigate and identify the possible reasons causing these variations by creating an integrated workflow comprised of two modeling sections using actual field data. Fracture Modeling; to assess the fracturing operation and obtain the fracture geometry and conductivity using StimPlan software. Reservoir Simulation; to test the fracture design by the performance of the well using Petrel and Eclipse software. The iterative process in the workflow also gives the ability to tailor the design to reach the maximum potential of the well. Three major reasons are suspected to be behind the underperformance of the investigated well. First, human errors in planning and gathering the required data for the stimulation job. Second, the stress contrast between the layers allows the fracture to propagate vertically giving more fracture height than length. Third, the fracture orientation, which has a great effect on the long-term performance by allowing the induced fracture to intersect with the formation and the natural fractures"--Abstract, page iii.
Author: Varun Mishra Publisher: ISBN: Category : Languages : en Pages :
Book Description
Horizontal wells are drilled to achieve improved reservoir coverage, high production rates, and to overcome water coning problems, etc. Many of these wells often produce at rates much below the expected production rates. Low productivity of horizontal wells is attributed to various factors such as drilling induced formation damage, high completion skins, and variable formation properties along the length of the wellbore as in the case of heterogeneous carbonate reservoirs. Matrix acidizing is used to overcome the formation damage by injecting the acid into the carbonate rock to improve well performance. Designing the matrix acidizing treatments for horizontal wells is a challenging task because of the complex process. The estimation of acid distribution along wellbore is required to analyze that the zones needing stimulation are receiving enough acid. It is even more important in cases where the reservoir properties are varying along the length of the wellbore. A model is developed in this study to simulate the placement of injected acid in a long horizontal well and to predict the subsequent effect of the acid in creating wormholes, overcoming damage effects, and stimulating productivity. The model tracks the interface between the acid and the completion fluid in the wellbore, models transient flow in the reservoir during acid injection, considers frictional effects in the tubulars, and predicts the depth of penetration of acid as a function of the acid volume and injection rate at all locations along the completion. A computer program is developed implementing the developed model. The program is used to simulate hypothetical examples of acid placement in a long horizontal section. A real field example of using the model to history match actual treatment data from a North Sea chalk well is demonstrated. The model will help to optimize acid stimulation in horizontal wells.
Author: Jaehun Lee Publisher: ISBN: Category : Languages : en Pages :
Book Description
Acid fracturing stimulation is one of the preferred methods to improve well productivity in carbonate reservoirs. Acid is injected into the fractured zone after a starter fracture is created in the near wellbore area by viscous fluid (pad). This results in propagation of a two-wing crack away from the perforations with simultaneous dissolution etching of the created surfaces. If the created etched surface is non-uniform, then after the treatment ends and the fracture face closes, a high conductivity path may remain in the formation, connected to the well. The important factors controlling the effectiveness of acid fracturing are the etched-fracture penetration and conductivity. In this research, I use the distributed volumetric sources (DVS) method to calculate gas production from a well stimulated by acid fracturing. The novel concept realized in this research is that, during the production process, the conductivity of the acid created fracture changes. I use the Nierode - Kruk correlation to describe this effect as a function of effective closure stress that in turn is determined from the flowing bottomhole pressure and minimum horizontal stress. By combining the well productivity calculation from the DVS method taking into account varying fracture conductivity with gas material balance, I obtain an improved model of gas production. The model is then used to not only forecast production from acid fractured wells but also to evaluate the known production history of such wells. Based on the concepts discussed above, I have developed a program called "Gas Acid" which is useful to optimize acid fracturing treatments and also suitable to infer created fracture parameters from known production history. The "Gas Acid" program has been validated with data from two Saudi Aramco gas wells. It was found that the production forecast obtained from the "Gas Acid" program matches the actual production history with reasonable accuracy and the remaining discrepancy could be resolved by taking into account refinement of the material balance. The refinement became necessary, because the "Gas Acid" program was developed for dry gas but the reservoir fluids in the field examples were classified as retrograde gas and wet gas. When accounting for the additional mass of gas "hidden" in the produced condensate, the match of forecast and actual data was improved considerably.
Author: Abdulwahab Alghamdi Publisher: ISBN: Category : Languages : en Pages :
Book Description
Acid fracturing is one of the preferred methods to stimulate wells in carbonate reservoirs. It consists of injecting an acid solution at high enough pressure to break down the formation and to propagate a two-wing crack away from the wellbore. The acid reacts with the carbonate formation and this causes the etching of the fracture surfaces. After the treatment, the created etched surfaces do not close perfectly and thatl eaves behind a highly conductive path for the hydrocarbons to be produced. We distinguish the issue of treatment sizing (that is the determination of the volume of acid to be injected) and the issue of creating optimum fracture dimensions given the size of the treatment. This is reasonable because the final cost of a treatment is determined mainly by the volume of acid injected and our goal should be to achieve the best performance of the treated well. The well performance depends on the created fracture dimensions and fracture conductivity and might change with time due to various reasons. This research evaluates two field cases from Saudi Aramco where acid fracturing treatment has been used to stimulate a carbonate formation. I investigated the following issues: a) how effective was the treatment to restoring the initial productivity, b) how did the productivity of the well change with time; c) what are the possible reasons for the change in performance, d) what are our options to improve acid fracture design in the future?Based on our research work both near-well liquid drop-out and fracture-conductivitydeterioration can impact the production in different proportion. Moreover, the fracturing model tends to overestimate the fracture conductivity in some cases as shown in SA-2. Also, the "Acid fracture Number" concept proves to be an effective way to evaluate the acid fracturing treatment. Several recommendations were made based on this research work as described in the last part of my thesis.
Author: Publisher: ISBN: Category : Languages : en Pages : 134
Book Description
The second year of this three-year research program to evaluate the effect of fracture closure on the recovery of oil and gas from naturally fractured reservoirs has been completed. The overall objectives of the study are to: (1) evaluate the reservoir conditions where fracture closure is significant, and (2) evaluate innovative fluid injection techniques capable of maintaining pressure within the reservoir. Simulation studies have been conducted with a dual porosity simulator capable of simulating the performance of vertical and horizontal wells. Each simulation model has been initialized with properties typical of the Austin Chalk reservoir in Pearsall Field, Texas. During year one, simulations of both vertical and horizontal well performance were made assuming that fracture permeability was insensitive to pressure charge. The results confirmed that horizontal wells could increase both rate of oil recovery and total oil recovery from naturally fractured reservoirs. During the second year the performances of the same vertical and horizontal wells were evaluated with the assumption that fracture permeability was a function of reservoir pressure. This required repetition of most of the natural depletion cases simulated in year one while invoking the pressure-sensitive fracture permeability option. To investigate sensitivity to in situ stress, two stress conditions were simulated for each primary variable. The water injection cases, begun in year one, were extended to include most of the reservoir parameters investigated for natural depletion, including fracture permeability as a function of net stress and the use of horizontal wells. The results thus far confirm that pressure-sensitive fractures degrade well performance and that the degradation is reduced by water injection pressure maintenance. Furthermore, oil recovery can be significantly increased by water injection pressure maintenance.
Author: Jun Ge Publisher: ISBN: Category : Languages : en Pages :
Book Description
The distributions of pore pressure and stresses around a fracture are of interest in conventional hydraulic fracturing operations, fracturing during water-flooding of petroleum reservoirs, shale gas, and injection/extraction operations in a geothermal reservoir. During the operations, the pore pressure will increase with fluid injection into the fracture and leak off to surround the formation. The pore pressure increase will induce the stress variations around the fracture surface. This can cause the slip of weakness planes in the formation and cause the variation of the permeability in the reservoir. Therefore, the investigation on the pore pressure and stress variations around a hydraulic fracture in petroleum and geothermal reservoirs has practical applications. The stress and pore pressure fields around a fracture are affected by: poroelastic, thermoelastic phenomena as well as by fracture opening under the combined action of applied pressure and in-situ stress. In our study, we built up two models. One is a model (WFPSD model) of water-flood induced fracturing from a single well in an infinite reservoir. WFPSD model calculates the length of a water flood fracture and the extent of the cooled and flooded zones. The second model (FracJStim model) calculates the stress and pore pressure distribution around a fracture of a given length under the action of applied internal pressure and in-situ stresses as well as their variation due to cooling and pore pressure changes. In our FracJStim model, the Structural Permeability Diagram is used to estimate the required additional pore pressure to reactivate the joints in the rock formations of the reservoir. By estimating the failed reservoir volume and comparing with the actual stimulated reservoir volume, the enhanced reservoir permeability in the stimulated zone can be estimated. In our research, the traditional two dimensional hydraulic fracturing propagation models are reviewed, the propagation and recession of a poroelastic PKN hydraulic fracturing model are studied, and the pore pressure and stress distributions around a hydraulically induced fracture are calculated and plotted at a specific time. The pore pressure and stress distributions are used to estimate the failure potentials of the joints in rock formations around the hydraulic fracture. The joint slips and rock failure result in permeability change which can be calculated under certain conditions. As a case study and verification step, the failure of rock mass around a hydraulic fracture for the stimulation of Barnett Shale is considered. With the simulations using our models, the pore pressure and poro-induced stresses around a hydraulic fracture are elliptically distributed near the fracture. From the case study on Barnett Shale, the required additional pore pressure is about 0.06 psi/ft. With the given treatment pressure, the enhanced permeability after the stimulation of hydraulic fracture is calculated and plotted. And the results can be verified by previous work by Palmer, Moschovidis and Cameron in 2007.
Author: Jurairat Densirimongkol Publisher: ISBN: Category : Languages : en Pages :
Book Description
Today, optimizing well stimulation techniques to obtain maximum return of investment is still a challenge. Hydraulic fracturing is a typical application to improve ultimate recovery from oil and gas reservoirs. Proppant fracturing has become one of the most widely considered alternatives for application in carbonate reservoirs. Especially in areas that have high closure stress, the non-smoothly etched surface created by acid fracturing may not remain open upon closing, resulting in decrease in fracture conductivity and unsuccessful stimulation treatment. In early years, because of the increase in the success of proppant fracturing, proppant partial monolayer has been put forward as a method that helps generate the maximum fracture conductivity from proppant fracturing treatment. However, this method was not widely successful because of proppant crushing and proppant embedment problems that result in losing conductivity. The ability to transport propping agents in available fracturing fluid was also poor and resulted in difficulties and failures to obtain proppant partial monolayer placement. For carbonate formations, acid fracturing is another effective stimulation method. Simpler operation and lower cost made the technique attractive in the field with plenty of successful experiences. The heterogeneity feature of carbonate formation brings a challenge to create sufficient conductivity. In cases of high closure formation, fracture conductivity is hard to sustain. This factor limited the applications of acid fracturing sometimes. In this study, laboratory tests were carried out using low concentrations of ultralightweight proppant to obtain partial monolayer proppant. Because of low specific gravity property of this proppant, it was claimed to help improve proppant transport inside the fracture. In this experimental study, the partial monolayer technique was examined with particular emphasis upon the impact of acid in possibly improving fracture conductivity of carbonate rocks. The technique is referred as "closed fracture acidizing". After obtaining a partial monolayer distribution on the fracture face, gelled acid was injected through the fracture face. Fracture conductivity before and after acid injection were evaluated. Experimental results showed clearly that acid injection does not enhance fracture conductivity of partial monolayer proppant fracturing. The more the volume of acid injection, the more rapidly fracture conductivity declines.
Author: Kyunghaeng Lee Publisher: ISBN: Category : Languages : en Pages : 514
Book Description
During waterflooding, or chemical EOR processes with polymers, fractures are frequently generated in injectors. This can have a profound impact on the process performance and reservoir management. A fracture growth model was developed and linked to a reservoir simulator that incorporates the effect of (i) particle plugging due to filtration of solids and oil droplets in the injected fluids; (ii) non-Newtonian polymer rheology (shear-thinning and -thickening) for polymer injection; and (iii) thermal stresses induced by cold water injection. Dynamic fracture growth, which results from the pore pressure increase due to particle plugging or complex polymer rheology, affects the well injectivity and reservoir sweep significantly. With the fracture growth model, simulations can be made not only to make more accurate reservoir sweep and oil recovery predictions, but also to help identify well patterns that may improve reservoir performance. In homogeneous reservoirs, the injectivity is significantly affected by the propagation of an injection induced fracture; but the ultimate oil recovery and reservoir sweep are relatively unaffected. In multi-layered reservoirs, however, reservoir sweep and oil recovery are impacted significantly by the fracture growth. The oil recovery results from our fracture growth model differ substantially from those obtained based on the assumption of no fracture generation or a static fracture. For polymer injection processes, the shear rate dependence of the polymer viscosity is critical in determining the injectivity, fracture growth, and oil recovery. In addition to vertical injection well fractures, horizontal injection well fractures have been simulated by using the fracture growth model. The reservoir stress distribution determines the fracture orientation near a horizontal well. When the minimum horizontal stress orientation is perpendicular to the horizontal injector, a longitudinal fracture is generated, while with the minimum horizontal stress orientation parallel to the injector, a transverse fracture is developed. The impact of static and dynamic transverse/longitudinal fractures on well injectivity and reservoir sweep has been investigated. The impacts of (i) lengths of horizontal injector and producer; (ii) location of water oil contact; (iii) sizes of transverse and longitudinal fractures; (iv) particle concentration in the water, were further investigated. The well injectivity model was validated successfully by history matching injection of water (with particles) and shear rate dependent polymer injection. The history match was performed by adjusting the effective particle concentration in the injected water or the shear rate dependent polymer rheology. Based on history matching the long-term injection rates and pressures, estimates of the fracture length were made. These fracture dimensions could not be independently measured and verified. Based on the simulation results recommendations were made for strategies for drilling well patterns, water quality and injection rates that will lead to better oil recovery.
Author: Cassandra Vonne Beatty Publisher: ISBN: Category : Languages : en Pages :
Book Description
Recently developed models of the acid fracturing process have shown that the differential etching necessary to create lasting fracture conductivity is caused by the heterogeneous distributions of permeability and mineralogy along the fracture faces. To predict the conductivity that can be created by acid in a particular formation, the models require information about these formation properties. This research aims to quantify correlation lengths using a geostatistical description of small scale heterogeneity to ascertain the distribution of permeability and mineralogy in a carbonate formation. The correlation length parameters are a first step in being able to couple acid transport and rock dissolution models at reservoir scale with a model of fracture conductivity based on channels and roughness features caused by small scale heterogeneity. Geostatistical parameters of small scale heterogeneity affecting wells in the Hugoton Field are developed. Data leading to their derivation are obtained from a combination of well logs and cores. The permeability of slabbed core is measured to yield vertical correlation length. Well logs are used to estimate permeability via an empirical relationship between core plug permeability and well log data for calculation of horizontal correlation length. A fracture simulator computes the acid etched fracture width for known treatment conditions. The resulting geostatistical parameters and acid etched width are used to predict acid fracture performance for a well in the Hugoton Field. Application of new model conductivity correlations results in a unique prediction for the acid fracture case study that differs from the industry standard. Improvements in low cost stimulation treatments such as acid fracturing are the key to revitalizing production in mature carbonate reservoirs like the Hugoton Field. Planning and development of new wells in any carbonate formation necessarily must consider acid fracturing as a production stimulation technique. Reliable models that accurately predict acid fracture conductivity can be used to make an informed investment decision.
Author: Publisher: ISBN: Category : Languages : en Pages :
Book Description
A three-year research program to evaluate the effect of fracture closure on the recovery of oil and gas from naturally fractured reservoirs has been completed. The overall objectives of the study were to: (1) evaluate the reservoir conditions for which fracture closure is significant, and (2) evaluate innovative fluid injection techniques capable of maintaining pressure within the reservoir. The evaluations of reservoir performance were made by a modern dual porosity simulator, TETRAD. This simulator treats both porosity and permeability as functions of pore pressure. The Austin Chalk in the Pearsall Field in of South Texas was selected as the prototype fractured reservoir for this work. During the first year, simulations of vertical and horizontal well performance were made assuming that fracture permeability was insensitive to pressure change. Sensitivity runs indicated that the simulator was predicting the effects of critical reservoir parameters in a logical and consistent manner. The results confirmed that horizontal wells could increase both rate of oil recovery and total oil recovery from naturally fractured reservoirs. In the second year, the performance of the same vertical and horizontal wells was reevaluated with fracture permeability treated as a function of reservoir pressure. To investigate sensitivity to in situ stress, differing loading conditions were assumed. Simulated natural depletions confirm that pressure sensitive fractures degrade well performance. The severity of degradation worsens when the initial reservoir pressure approaches the average stress condition of the reservoir, such as occurs in over pressured reservoirs. Simulations with water injection indicate that degradation of permeability can be counteracted when reservoir pressure is maintained and oil recovery can be increased when reservoir properties are favorable.
Author: Muaath Alansari
Author: Varun Mishra
Author: Jaehun Lee
Author: Abdulwahab Alghamdi
Author: 
Author: Jun Ge
Author: Jurairat Densirimongkol
Author: Kyunghaeng Lee
Author: Cassandra Vonne Beatty
Author: